The Producers 2018: BP increasing production without drilling

Company makes the case for redefining the measurements for activity at aging fields like Prudhoe Bay

Eric Lidji

for Petroleum News

BP Exploration (Alaska) Inc. is making a strong case against using drilling as the key metric for measuring development activity, at least when it comes to aging oil fields.

The local subsidiary of the international company reported notable production increases at many of its fields at the Prudhoe Bay unit over the past year and strong gains in efficiency at other fields, while also reporting a notable decline in drilling activity.

The company has been working over existing wells and refining its approach to enhanced oil recovery at the oldest and largest oil field on the North Slope. Describing its current strategy in a recent plan of development for the Initial Participating Areas at Prudhoe Bay, the company wrote, “While drilling was the key driver for production during the development phase of the IPA, now that the field is in production phase, large scale drilling programs (i.e., more than 50 new penetrations per year) have largely been replaced by operations efficiency increases, hundreds of wellwork jobs each year to maintain and enhance existing wellstock (including accessing rich gas for increased liquids production), and reservoir management techniques as the key drivers.”

BP files three plans of development each year for the Prudhoe Bay unit - one for the Initial Participating Areas early in the year, one for the Greater Point McIntyre Area in the middle of the year and one for the Western Satellites toward the end of the year.

Initial Participating Areas

The Initial Participating Areas, or IPA, covers the initial oil and gas caps discovered at Prudhoe Bay and is the largest of the three administrative regions at the unit.

BP expects development drilling to continue to play a role at the IPA, depending on economic conditions and the ability to identify worthwhile targets. But the company is crediting most of its production activity at the IPA on its ongoing wellwork program.

The IPA produced 186,800 barrels of crude oil and condensate per day in 2017 and delivered 68.19 million barrels to the trans-Alaska oil pipeline last year. Those rates were down from 197,900 bpd and 72.43 million cumulative barrels during 2016.

The IPA also produced 42,000 barrels of natural gas liquids per day in 2017 and delivered 15.3 million barrels to the trans-Alaska oil pipeline. Those rates were down from 38,000 bpd and 13.9 million cumulative barrels during 2016.

While acknowledging the effect of natural declines at the aging field, the company attributed the production decline, in part, to a turnaround at Gathering Center No. 1. (The primary goal of the turnaround was to replace corroded steel piping use for wet gas.)

According to the company, operational efficiency increased two percentage points to 85 percent in 2017, which helped partially offset some of the declines in production.

BP expects IPA crude and condensate production of 150,000 to 187,000 bpd in 2018 with associated NGL production between 30,000 and 46,000 bpd.

The development program planned at the Initial Participating Areas for this current year involved a notable reduction in drilling with a slight increase in well work activity.

BP planned to drill 14 wells this year - five rotary and nine coiled - down from 27 wells in 2017 - five rotary and 22 coiled. Rigged workover activity was expected to increase to three wells from one, largely with the goal of returning shut-in wells to active service.

The company expected to perform approximately 400 rate-adding well work jobs this year and approximately 700 non-rate-adding jobs “as well as an active, fieldwide reservoir surveillance program driving these activities,” according to BP. By comparison, the company performed 1,000 well work jobs last year, of which 386 added production.

A focus area for BP in 2017 was recovering condensate from the Sag River gas cap. The project involved plugging “uncompetitive” Ivishak production wells and adding perforations higher in the wellbore to target the gas cap of the Sag River formation.

The company undertook this process at 29 wells located at pads in the Gathering Center No. 1, Gathering Center No. 3, Flow Station No. 1 and Flow Station No. 3 regions. The work yielded 7,000 bpd at “competitive” gas-to-oil ratios by the end of the year. The entire program yielded 12,000 bpd from 650 million cubic feet. The company expects to undertake the process at 10 existing Ivishak wells this year.

Greater Point McIntyre

For several years, BP has said that the future of the development work in the Greater Point McIntyre Area would depend on the results of the North Prudhoe seismic survey.

The company wrapped up the survey in April 2015 and completed final merged Pre-Stack Depth Migration processing in September 2016 but only finished interpreting the data in January 2018. Although the company said that the survey has already improved its understanding of flank opportunities and noted that it is currently evaluating coil sidetrack operations, the plans for the coming year does not reflect the survey results.

Even so, BP reported noteworthy production increases at most of the fields in the area.

The Point McIntyre field produced 14,800 bpd (and 5.4 million barrels total) of crude oil, condensate and natural gas liquids during the year ending March 31, 2018, up from 12,400 bpd (and 4.5 million barrels total) during the previous year.

Although the company did not drill any new wells at Point McIntyre, it maintained “active wellwork and scale inhibition programs.” The work included a recompletion of P1-09 to access the Ivishak formation, welding on P1-18, a rigged workover on P1-04 to repair a leak and fracture operations on the low producing P1-20 and P1-23 wells.

The recently completed year was the first full year since BP returned the STP 36-inch pipeline to service in October 2016, allowing production to go to Gathering Center No. 1, rather than the Lisburne Production Center. The line had been out since November 2011.

For the coming year, BP is planning a project to expand miscible injectant at the PM-1 pad, similar to a project undertaken at the PM-2 pad during a previous development year.

The Lisburne field produced 13,800 bpd (and 5.1 million barrels total) of crude oil, condensate and natural gas liquids during the year ending March 31, 2018, up from 10,700 bpd (and 3.9 million barrels total) during the previous year.

BP drilled one well - the onshore L3-25 well into the Wahoo interval - and began drilling a second - the coastal NK-26A well into the Alapah interval - at Lisburne during the reporting period. The company performed 30 rate-adding workovers on 25 wells.

The company plans to drill three wells during the year ending Sept. 30, 2019 - L3-22A, L5-03 and L5-25A - and additional unidentified locations, pending well results.

Lisburne produced 83 billion cubic feet of natural gas during the reporting year, of which 54.5 billion was injected into the Lisburne Gas Cap to improve reservoir pressure. A related Lisburne Gas Cap Water Injection pilot project became permanent in early 2017.

The high gas-to-oil ratio at Lisburne requires BP to cycle wells through periods of production for periods of days or weeks, rather than allowing for continuous production.

The four remaining fields in the region account for minimal production.

The Niakuk field produced 1,200 bpd (and 436,000 barrels total) of crude oil, condensate and natural gas liquids during the year ending March 31, 2018, down from 1,300 bpd (and 478,000 barrels total) during the previous development year.

The company performed work on the NK-27 well and conducted a test on the NK-43 well to determine the appropriate allocation split between the Sag River and Kuparuk.

The company conducted an evaluation of potential infill and peripheral drilling opportunities during the year ending March 31, 2018, using some of the seismic data.

The Raven field produced 1,050 bpd (and 390,000 barrels total) of crude oil, condensate and natural gas liquids during the year ending March 31, 2018, up slightly from 940 bpd (and 340,000 barrels total) during the previous reporting year.

BP began drilling the horizontal NK-14B well into the Sag River formation in March 2017. The well was developed on a tract basis to gather information for future work.

But the well casing leaked after three months, requiring the company to shut in the well from September 2017 to March 2018. The well has since been returned to production.

The company also drilled the NK-15Ai injector well in February 2018 and plans to convert the NK-65Ai injector to a producer once NK-15Ai begins operations.

The North Prudhoe Bay field and West Beach field have been shut-in since the early 2000s. North Prudhoe Bay had produced 2.1 million barrels cumulative of crude oil and condensate before the WB-03 well was taken offline in February 2000. West Beach produced 3.37 million barrels of crude oil before it was taken offline in early 2001.

Western Satellites

BP reported increased production at four of the five fields in the Western Satellites region, after reporting declines during the previous year. In its most recent plan of development, the company reported increased oil production at the Borealis, Midnight Sun, Orion and Polaris fields at the west end of the Prudhoe Bay unit. The company reported a slight decline at the Aurora field that essentially constituted flat production.

BP made no firm drilling commitments at the Aurora field for the coming year but said it expected to continue its existing workover regimen. The company is evaluating potential infill drilling targets identified from its geological models, including recent well results.

The company performed 55 workover jobs on existing producers and injectors at the satellite. The projects included tree change out, gas lift optimization, hot oil treatments, safety valve work and vertical support member work. Fourteen of the 55 jobs added production. The remainder either sustained production or addressed maintenance issues.

In its plan, the company listed several projects: It sidetracked the S-200A well in mid-2017 and brought the well into production before the end of that year. It performed hydraulic fracturing on the S-129 well in May 2018 and the S-113B well in June 2018.

As part of a tertiary recovery process underway at the field over the past 15 years, the company also injected miscible injectant into five water-alternating-gas injectors.

The Aurora field came online in November 2000 after several months of initial development drilling. As of the end of June 2018, Aurora had 33 active wells from S pad (18 producers and 15 injectors) with oil processed at Gathering Center No. 2.

Aurora field produced 4,609 bpd in the year ending June 30, 2018, down from 4,696 bpd the previous year. Cumulative production reached 45.1 million barrels.

Borealis and Midnight Sun

BP made no firm drilling commitments at the Borealis field for the coming year but said it expected to workover wells and cycle high gas-to-oil ratio wells “as needed.”

“The Borealis owners will continue to evaluate the optimal number of development wells and their locations throughout the life of the reservoir,” the company wrote. “The dynamic model for the Borealis field will be used to evaluate potential drilling targets.”

The company performed 37 workover operations at Borealis in the year ending June 30, 2018, for purposes similar to those at the Aurora field. Nine of those operations added production, while the remainder sustained production or addressed maintenance issues.

BP drilled the V-137 grass roots well in the fourth quarter of 2017 but ultimately suspended drilling operations “due to structure coming in deep.” The company drilled the L-118L1 lateral in the first quarter of 2018 and brought the well online in the third quarter. The company also plugged and abandoned the V-119 well during the year.

As part of its tertiary recovery program begun at the Borealis field in June 2004, the company also injected miscible injectant into seven water-alternating-gas injectors.

The Borealis field came online in November 2001, following several months of initial drilling. As of the end of June 2018, Borealis had 49 active wells: 22 wells at L pad (13 producers and nine injectors), 19 wells at V pad (11 producers and eight injectors) and eight wells at Z pad (four producers and four injectors) and was processed at GC-2.

Borealis produced 7,914 bpd during the year ending June 30, 2018, up considerably from 6,040 bpd the previous year. Cumulatively, the field had produced 86 million barrels through the end of June 2018, according to figures from BP.

BP is not planning new wells at the Midnight Sun field for the coming year, although it plans to convert the E-100 injector to an Ivishak producer and could begin sidetracking maturing wells at the field as the benefits of water-alternating-gas injection are realized.

Midnight Sun was initially developed in 1997. As of the end of June 2018, the field had six active wells: the E-101 and E-102 producers, the E-100, E-103 and E-104 water injectors and the P1-122 water-alternating-gas well. The most recent was drilled in early 2015. Oil production is comingled at E pad and processed at Gathering Center No. 1.

Midnight Sun produced 1,158 bpd in the year ending June 30, 2018, up from 983 bpd the previous year. Cumulatively, the field had produced 21.6 million barrels through the end of June 2018, according to figures provided by the company.

Orion and Polaris

BP made no firm drilling commitments for the Orion field for the coming year but said it would continue its workover program and would evaluate sidetrack options at L pad.

The company performed 75 workover jobs at Orion in the year ending June 30, 2018, for purposes similar to those at other satellites. Eleven of those jobs added production, while the remainder either sustained existing production or addressed maintenance issues.

The company changed out waterflood regulating valves on 13 injection wells. The company also started drilling the L-205A sidetrack in the fourth quarter of 2017 and brought the well into production in the second quarter of this year. The well is the first vertical frack packed producer in the Orion participating area, according to the company.

BP is planning several near-term projects at Orion, some of which have been on the agenda for years. Several of these projects address sand production at the Orion field.

The company is studying possible improvements to sand-handling technology installed at GC-2 in 2012 and 2013. The technology was intended to address sand-laden viscous oil from Orion but, so far, has failed to yield the level of improvement desired by BP.

Additionally, BP is looking for ways to address the significant downtime affecting viscous wells in the northwest portion of the Orion participating area. Those wells have been down nearly half the time in recent years due to sand production, matrix bypass events and downhole equipment failures. The company is studying alternate well designs.

In the recently completed development year, BP tested some alternate well designs on the L-200 and L-203 producers, which have often been hampered by sand production.

One of the longest-desired and longest-delayed projects at Orion is the proposed I pad, which the company claims is dependent “upon the results of sand control technology deployed in the Schrader Bluff Formation and the business environment.” Work on the recent L-205A project provided some information in that regard, according to BP.

The Orion field came online in April 2002, following several months of initial development drilling dating back to December 2001. As of the end of June 2018, the field had 33 active wells: 12 wells at L pad (four producers and eight injectors) and 21 wells at V pad (five producers and 16 injectors). Orion oil production is processed at GC-2.

Orion produced 3,900 bpd in the year ending June 30, 2018, up from 3,469 bpd the previous year. Cumulatively, the field had produced 35.1 million barrels through the end of June 2018, according to figures provided by the company.

BP made no firm drilling commitments for the Polaris field for the coming year but said it would continue its workover program with an eye toward mitigating declines.

The company did not drill or complete any new wells at Polaris during the year ending June 30, 2018 but performed 27 workover jobs on existing producers and injectors to minimize declines in oil production. Twelve of those jobs added production, while the remainder either sustained existing production rates or addressed maintenance issues.

Many of the projects occurring at Polaris and planned for the immediate future, particularly those involving viscous oil and sand control, overlap with those at Orion.

BP is studying ways to use existing well designs as M pad and S pad to access areas at Polaris with good oil mobility. The company began evaluating two new waterflood enhanced oil recovery patterns at S pad during the reporting year ending June 2018.

“If proven to be viable, development of additional areas at S pad with good oil mobility would be limited to the number of donor wellbores and surface slots available that are able to reach the target without anti-collision issues. The modeling and completions studies work at S pad will transfer to other areas in both the Orion (participating area) and Polaris (participating area),” the company wrote in its plan. A wider viscous oil development at M pad and S pad is contingent on sand control in the Schrader Bluff.

The Polaris field came online in November 1999, after two years of development drilling.

As of the end of June 2018, the field had 24 active wells: four wells at S pad (one producer and three injectors) and 20 wells at W pad (seven producers and 13 injectors).

Polaris oil production is processed at GC-2.

Polaris produced 4,158 bpd in the year ending June 30, 2018, up from 3,891 bpd the previous year. Cumulatively, the field had produced 23.2 million barrels through the end of June 2018, according to figures provided by the company.